Crude oil and natural gas residing in subterranean porous formations are produced by drilling wells into the formations. Oil and/or natural gas flow into the well driven by the pressure gradient which exists between the formation and the well, gravity drainage, fluid displacement, and capillary action. Typically, surface pumps are required to supplement the natural driving forces to bring the hydrocarbons to the surface.
Most wells are hydraulically fractured to increase flow. The drill pipe casing section adjacent to the zone to be fractured is perforated using explosive charges or water jets. Then a fracturing fluid is pumped down the drill pipe a: a rate and pressure high enough to fracture the formation. The fractures propagate as vertical and/or horizontal cracks radially outward from the wellbore.
Solid particles called proppants are dispersed into the fracturing fluid. Proppants lodge in the propagated fractures and hold them open after fracturing fluid hydraulic pressure is released and the fracturing fluid flows back into the well. Without proppants, the cracks would close and the increased permeability gained by the fracturing operation would be lost. Proppants must have sufficient compressive strength to resist crushing, but also must be sufficiently non-abrasive and non-angular to preclude cutting and imbedding into the formation.
The primary consideration in selecting a proppant is the pressure in the subterranean formation to be fractured. Suitable proppants include sand, graded gravel, glass beads, sintered bauxite, resin coated sand and ceramics. In formations under moderate pressure, 6000 psi or less, the most commonly used proppant is ordinary screened river sand. For formations with closure stresses 6000 to about 10,000 psi, sand proppants coated with a thermosetting phenolic resin are preferred. Sintered bauxite, glass beads and ceramics are used to fracture wells with closure pressure in the range of 10,000 to 15,000 psi.
The rheological requirements of a fracture fluid are highly constraining. To adequately propagate fractures in the subterranean formation, a fracturing fluid must exhibit low leakage rate of liquids into the formation during the fracturing operation. Also, the fracturing fluid must have sufficient body and viscosity to transport and deposit large volumes of proppant into the cracks in the formation formed during fracturing. The fracturing fluid must readily flow back into the well after the fracturing is complete and not leave residues that impair permeability and conductivity of the formation. Finally the fracturing fluid must have rheological characteristics which permit it to be formulated and pumped down the well without excessive difficulty or pressure drop friction losses.
The most commonly used fracturing fluids are water-based compositions containing a hydratable high molecular weight polymeric gelling material which increases the viscosity of the fluid. Thickening the fluid reduces leakage of liquids from the fracture fissures into the formation during fracturing and increases proppant suspension capability.
A wide variety of hydratable viscosifiers are used in fracturing fluid formulations including polysaccharides, polyacrylamides and polyacrylamide copolymers. Polysaccharides are currently favored. Particularly desirable polysaccharides include galactomannan gum and cellulose derivatives. Specific polysaccharides include guar gum, locust bean gum, carboxymethylguar, hydroxyethylguar, hydroxypropylguar, carboxymerhylhydroxypropylguar, carboxymethylhydroxyethylguar, sodium-hydroxymethyl cellulose, sodium carboxymethylhydroxyethyl cellulose, and hydroxyethyl cellulose. Generally, the molecular weights of the hydratable polymers used in fracturing fluids range from about 500,000 to about 3,000,000. The ratio of apparent viscosity of the fracturing fluid relative to water at shear rates encountered in well fractures is between from about 50 to about 2000. Currently, viscosifier concentrations in fracturing fluids range from about 10 to about 100 lbs of viscosifier per 1000 gallons of fracturing fluid.
Over the years the depth of oil and gas wells steadily increased to maintain reserves and production. Downhole temperatures increase with depth. Initially, the reduced viscosity encountered as downhole temperatures increased was compensated by increasing the concentration of viscosifier gelling agent in the fracturing fluids. However, as well depths continued to increase, the concentrations required to maintain adequate downhole viscosity reached the limit past which the fracturing fluid became too difficult to mix and pump at the surface. The solution was to use less polymer viscosifier and to incorporate crosslinking compounds into the fracturing fluids. Crosslinkers form chemical bonds between the viscosifier polymer molecules which raise the viscosity of the solution.
The crosslinking is between cis position hydroxyl groups on adjacent polysaccharide thickener polymer molecules. Common crosslinking agents include polyvalent ions in their high valance state such as Al(IV), Ti(IV), Zr(IV). Also, borate ions are effective crosslinkers for polysaccharides.
The crosslinking agents react with sufficient time delay so that the fracturing fluid may be formulated and pumped down the well. Crosslinking occurs as the fracture fluid heats up as it approaches the formation providing the viscosity enhancement necessary to promote fracturing and proppant transport.
When the fracturing operation is complete and pressure on the formation is reduced, the fracturing fluid flows back out of the formation into the well so that production of oil or gas can begin. To induce recovery of fracture fluid, the viscosity of the fracturing fluid is reduced ("broken") so that it can freely flow back out of the formation and into the well.
Hydratable polymers decompose spontaneously in time from either bacteriological or thermal degradation but the natural degradation is too slow and too much production time is lost. Accordingly, a chemical agent referred to as a "breaker" is added to the fracturing fluid to accelerate viscosity reduction. Breakers operate by severing the backbone chain of the hydrated polymer. The type and concentration of breaker is selected so that the viscosity of fracturing fluid remains sufficiently high to be effective until the fracturing operation has been completed.
Enzyme breakers such as alpha and beta amylases, amyloglucosidase, oligoglucosidase invertase, maltase, cellulase, and hemicellulase are commonly used for wells having a bottomhole temperature below about 150.degree. F. and with fracturing fluids with pH between about 3.5 and 8. Enzymes catalyze the hydrolysis of glycosidic bonds between the monomer units of polysaccharides.
Peroxygen compounds are the preferred breakers for higher temperature downhole temperatures in the range from about 140.degree. F. to about 250.degree. F. temperature range. They form free radicals which attack and sever the backbone of gel polymer chains. Peroxides generally decompose over a narrow temperature range characteristic of the peroxide. Accordingly, premature viscosity breaking can be precluded by selecting a peroxygen with a decomposition temperature close to the temperature in the fractured formation so that peroxide does not decompose until it is heated to formation temperature.
Commonly used peroxygen breakers include dichromates, permanganates, peroxydisulfates, sodium perborate, sodium carbonate peroxide, hydrogen peroxide, tertiarybutylhydroperoxide, potassium diperphosphate, and ammonium and alkali metal salts of dipersulfuric acid. Typical breaker addition rates range from about 0.1 to 10 lbs. per thousand gallons of fracturing fluid. Breakers are usually added to the fracturing fluid at the surface "on-the-fly" as the fluid is being pumped down the well.
A significant number of hydrocarbon bearing subterranean formations can not be fractured by conventional fracturing fluids. These problematic formations include hydrocarbon reservoirs that are under low pressure, subterranean formations that exhibit low permeability to fluid flow, and formations in which permeability is reduced when they absorb water. For example, clay in formations swells when it absorbs water which reduces permeability. Also, fracturing fluids do not readily flow back out of these difficult formations when the fracturing operation is complete; the fluids remain in the formations and they impede the flow of hydrocarbons to the well.
It is important to limit water leakage from fracturing fluids into the formation when fracturing problematic sensitive formations because the water can permanently damage the formations. Also, excessive fluid leakage interferes with fracturing and proppant deposition.
The problem of fluid leakage control in well fracturing can be analogized to filtration. When fracturing is initiated, some fracture fluid liquids unavoidably flow into the formation. But as the fracturing operation proceeds, fluid leakage into the formation is progressively restricted by continuous deposition of the polymer thickening agents used in fracturing fluids. The thickening agents form a thin film over the fracture matrix which is referred to in the fracturing technical literature as a "filtercake." The filtercake must be disrupted after the fracturing operation is completed because if it remains it impedes flow of oil and gas to the well. Excessive buildup of filtercake must be avoided since thick filtercakes are not readily removed. Control and limitation of residual filtercake is particularly important when fracturing problematical subterranean formations. Clearly, for problematical formations, fracturing fluids must provide an optimal balance between minimizing fluid leakage, filtercake buildup thickness and filtercake removal.
An alternative to the conventional all liquid fracturing fluids was developed to provide this critical balance of characteristics and found to be effective for problematical formations: foamed fracturing fluids. Foamed fracturing fluids are media in which a relatively large volume of gas is dispersed in a relatively small volume of liquid, usually with the aid of a surfactant which reduces the surface tension of the fluids. The most commonly used gases for foamed fracture fluids are nitrogen and carbon dioxide because they are non-combustible, readily available and relatively cheap. Currently, foamed fracturing fluids are predominantly water based although oil and alcohol based foams are used.
Capitalizing on the rigid two phase structure and favorable rheological characteristics of foams, foamed fracturing fluids have been formulated which exhibit high proppant carrying and transport capacity. The foams induce manageably low frictional pressure drop as the fluid is pumped down the well and into the formation and effectively fracture subterranean formations. Moreover, foams readily flow back out of the formation into the well when the fracturing operation is complete.
Surfactants used in foamed fracturing fluid formulations to promote and stabilize the gas-liquid dispersions are soap-like molecules containing a long hydrophobic paraffin chain with a hydrophilic end group. Surfactants include cationic, anionic, nonionic or is amphoteric compounds such as for example, betaines, sulfated or sulfonated alkoxylates, alkyl quarternary amines, alkoxylated linear alcohols, alkyl sulfonates, alkyl aryl sulfonates, C10-C20 alkyldiphenyl ether sulfonates and the like. Suitable surfactants include for example polyethylene glycols, ethers of alkylated phenol, sodium dodecylsulfate, alpha olefin sulfonates such as sodium dodecane sulfonate and trimethyl hexadecyl ammonium bromide. Surfactants are added in concentrations which range typically from about 0.05 to about 2 percent of the liquid component by weight (from about 0.5 to about 20 gallons per 1000 gallons of liquid).
Foamed fracture fluids are superior to conventional liquid fracturing fluids for problematic and water sensitive formations because foams contain less liquid than liquid fracturing fluids and have less tendency to leak. Also, foams have less liquid to retrieve after the fracturing operation is complete. Moreover, the sudden expansion of the gas in the foams when pressure in the well is relieved after the fracturing operation is complete promotes flow of residual fracture fluid liquid back into the well.
The gas volumetric fraction or "quality" of useful foamed fracture fluids is typically in the range of from about 60 volume percent to about 8C volume percent gas. However, stable foams with qualities of up to about 95% can be produced. In general, the viscosity of the foamed fluid increases with increasing quality. Proppant also increases the apparent viscosity of foamed fracture fluid.
Procedures for making and using foamed fracturing fluids are described in U.S. Pat. No. 3,937,283 to Blauer et al., and in U.S. Pat. No. 3,980,136 to Plummer et al. Briefly, these patents teach how to produce stable foam fracturing fluids using nitrogen, water, a surfactant and a sand proppant. The foam quality ranges between 53% to 99%. The foam is pumped down the well and into the formation at a pressure sufficient to fracture the formation. When the fracturing operation is complete, the pressure on the well is relieved at the wellhead. The foam is carried back into the well by the rush of expanding gas when pressure on the foam is reduced.
U.S Pat. Nos. 3,195,634 to Hill, 3,310,112 to Nielson et al., 3,664,422 to Bullen, and 4,627,495 to Harris et al., describe fracturing techniques using carbon dioxide as the gas phase. First, an emulsion of liquefied carbon dioxide and water is formed using a surfactant to promote dispersion. Proppant is added to the emulsion and the emulsion-proppant slurry is pumped down the wellbore into the formation at a pressure sufficient to fracture the subterranean formation. Downhole temperatures are above the critical temperature of carbon dioxide so the liquid carbon dioxide becomes a supercritical fluid as the emulsion approaches the subterranean formation forming a stable foam.
After the fracturing operation is complete the pressure on the well is reduced at the wellhead. The foam is broken and the rush of depressurized and expanding carbon dioxide back into the well entrains the residual fracturing fluid liquids and carries them out of the formation.
Carbon dioxide foams have deeper well capability than nitrogen foams. Carbon dioxide emulsions have greater density than nitrogen gas foams so that the surface pumping pressure required to reach a corresponding depth is lower with carbon dioxide than with nitrogen. Moreover, the higher density imparts greater proppant transport capability, up to about 12 lb of proppant per gal of fracture fluid. Carbon dioxide is acidic so that crosslinking agents compatible with carbon dioxide foams are generally limited to those active in the pH range of about 3 to about 5. Of the common crosslinkers this excludes borates from use with carbon dioxide because borates are not effective below a pH of about 8.
When first introduced commercially in the 1970's, the foamed fracture fluids were simply foams made from nitrogen or carbon dioxide and water. The proppant carrying capacity of these rudimentary foams was low, limited to about one or two lbs per gal, and fluid leakage into the formation was high, which limited fracturing applications to low pressure reservoirs typically sandstone, carbonate and shale reservoirs.
With time, incentives to extend foam procedures into deeper and higher pressure reservoirs increased. Higher pressure applications required more proppant carrying capacity, better leakage control, and foam stability at higher temperatures. These requirements were met by adding water soluble polymer gel viscosfiers to the aqueous phase. The hydratable polymers commonly used in liquid fracturing fluids are suitable also for foams, including guar and hydroxypropyl guar.
Foaming technology was steadily improved and new surfactants were employed that produced foams that were stable at higher temperatures encountered in deeper wells. By 1980, technology had developed that supported large scale hydraulic foam fracturing treatments which placed over one million lbs of sand proppant at carrying concentrations of up to 4 lb/gal of fracturing fluid in formations at temperatures as high as 270 F. Advances in carbon dioxide-water emulsion technology further extended treatment depth capability.
Shortly after delayed polymer gel crosslinkers were developed for conventional fracturing fluids in the early 1980's they were also added to the liquid phase of both nitrogen and carbon dioxide foamed fracturing fluids. Crosslinking the polymers increases the viscosity of the foams, typically, by a factor of two or more, which increases the proppant carrying capacity of the foams.
Another advantage of crosslinked foams is that they generally create wider fractures than uncrosslinked foams. The fractures generally are shorter for a given volume of fluid pumped. A shorter, wider fracture has less total fracture area exposed which limits fluid leakage into the formation and Improves placement of proppant in the fractures.
The same crosslinking agents that are used in conventional liquid fracturing fluids--Ti, Zr, Al, borates--are used in foamed fracturing fluids. Proppant concentrations up to as high as about 12 lb per gal have been reported using a crosslinked carbon dioxide foam.
As previously discussed, it is desired that most of the polymer filtercake deposited in the formation during fracturing be removed after the fracturing operation is complete to restore production capability. Foamed fracturing fluids leave thinner filtercakes than conventional liquid fracturing fluids thereby facilitating removal. Filtercakes from foams range between 0.04 to 0.15 mm in thickness compared with filtercake thicknesses of about 0.75 to 1.0 mm typically encountered with conventional liquid fracturing fluids.
Foamed fracturing fluids exhibit low liquid leakage into the formation because foams inherently have low liquid concentrations and the stable two-phase structure characteristic of foams minimizes leakage and promotes proppant transport and placement capability.
Today, even though foamed fracturing fluids cost 10% to 20% more than their fluid counterparts, they continue to be the stimulant of choice for fracturing problematic formations e.g., formations which are damaged by water leakage, or have low pressure or poor permeability.
Uncrosslinked foamed fluids are the cleanest fracturing fluids available; they leave the least residual filter cake and provide the maximum post fracture conductivity and formation permeability. However, experience has shown that filtercakes from crosslinked gels may be difficult to remove and may significantly interfere with production. The residual crosslinked filtercake impairs the permeability and conductivity of the formation, significantly reducing production rate and ultimate recovery of oil and gas from the subterranean bearing formation. This presents a problem since crosslinking is required in many foamed fracturing fluid applications to control fluid leakage in the formations and to increase the apparent viscosity of the foam so that the foam can fracture the formation effectively and exhibit the required proppant transport and placement capacity.
For the foregoing reasons there is a need for a roamed fracturing fluid that has the performance advantages of crosslinked gel foams but which deposits a filtercake which can be substantially completely removed after the fracturing operation is completed.